Methods for controlling temperatures in the environments of gas and oil wells

ABSTRACT

Methods and apparatus are provided for controlling temperatures in the environments of oil, gas condensate, or gas wells. Methods are provided for reducing the melting of glaciers and ice dams through the deployment of hydrate-forming substances. Active methods involve employing a vapor-compression refrigerator/heat pump cycle in an annulus lying between the relatively hot production string and the relatively cold outer pipe. Passive methods include: deploying cold hydrate-forming fluids into the external ice-laden environment of an oil, gas condensate, or gas well in a permafrost area and allowing those hydrate forming fluids to mix with any melt-water that may be present or that may subsequently form due to the loss of heat from the oil, gas condensate, or gas well. Mixtures of the hydrate forming fluids and the melt-water will set up into a solid having a much higher melting point and a much lower thermal conductivity than those of ice.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of the filing date of and priority to U.S. Provisional Application Ser. No. 61/207,464 entitled “Methods for controlling temperatures in the environments of gas and oil wells” and filed Feb. 12, 2009, Confirmation No. 3995. Said provisional application is incorporated by reference herein.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments disclosed herein relate generally to the recovery of oil, gas condensate, and gaseous hydrocarbons. In particular, embodiments disclosed herein relate to the recovery of oil, gas condensate, and gaseous hydrocarbons from subterranean petroliferous reservoirs wherein there is a need to limit the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string of pipe.

2. Background Art

Production of oil, gas condensate, and natural gas from subterranean oil and gas reservoirs is a well-established practice. Oil, gas condensate, and natural gas production has for the most part been achieved through drilling wells into deep reservoirs where natural gas, frequently in association with condensate, crude oil, and water, may be trapped under a layer of cap rock. The well is lined with a casing that is cemented to the surrounding formation to provide a stable wellbore. The casing is then perforated at the reservoir level to allow gas and reservoir fluids to flow in through the casing and then to the surface through tubing inside the casing.

After entering the casing via the perforations, the oil, gas condensate, and natural gas enter the tubing string(s) where they flow to the surface, through valves, a production gathering center, and to a pipeline. The cased well method facilitates control of the flow of gas from a high-pressure reservoir and is well suited for production from porous rock or sand formation material. If the reservoir has sufficient integrity, the producing formation may not need to be stabilized with casing, and production may be initiated through various types of open-hole completions.

In some cases, the cased well method or the open-hole completion methods are practiced under conditions in which there is a need to limit the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string. Examples of such circumstances include those in which there may be a deleterious effect in the production string due to the loss of heat from the produced fluids. These effects include the formation of wax, asphaltenes, or hydrates in the produced fluids when the produced fluids cool to an extent that leads to the formation of these solid materials in such a form that the solids can begin to build up on the walls of the production string and begin to choke off production.

Other circumstances wherein there is a need to limit the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string include those when there are one or more fluid filled, trapped annuli. When the heat of the produced fluids leaks out into one of these fluid filled, trapped annuli, the fluid therein can expand, and as there is no space for expansion because the annulus is trapped, the pressure begins to build up in the annulus. There have been instances recorded wherein pressure build-up in a trapped outer annulus has led to an inward collapse leading to loss of flow through the producing string.

Yet other circumstances wherein there is a need to limit the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string include those when the well is constructed through a permafrost zone and there is a need, for environmental protection and to maintain the mechanical integrity of the wellbore, to limit the melting of the ice in the permafrost. Permafrost is a thick layer of frozen surface ground which may be several hundred feet thick and presents a great obstacle to the removal of relatively warm fluids through a well pipe. Particularly, warm fluid in the well pipe causes thawing of the ice within the permafrost in the vicinity of the well resulting in subsidence which can impose compressive and/or tension loads high enough to rupture or collapse the well casing and hence allow the escape of well fluids, with disastrous environmental consequences.

Two strategies well known in the art for diminishing the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string are the deployment of vacuum insulated tubulars (VIT's) and insulating annular fluids (IAF's), sometimes referred to as insulating packer fluids (IPF's). VIT are typically 40 foot sections of pipe each insulated over about 39 feet by being surrounded by a larger concentric pipe sealed at each end to the inner, 40 foot pipe, creating an annulus over most of the length of the pipe section as an integral part of the pipe segment and from which annulus virtually all of the contents are evacuated. If we think of an ultra-low pressure gas (i e., a vacuum) as a fluid, then VIT is one example of an insulating annular fluid, inasmuch as the vacuum “fluid” does not transfer much heat, either through conduction or convection. Conventional annular fluids or packer fluids are liquids which are pumped into an annular opening between a casing and a wellbore wall or between adjacent, concentric strings of pipe which may or may not extend into a wellbore. If an annular fluid is developed from a base fluid with low thermal conductivity and engineered to have rheological properties that resist the onset of convection, then the annular fluid will have insulating properties. Such fluids are especially useful in oil or gas well construction operations conducted in low temperature venues of the world, for example, those areas in very deep waters or having permafrost.

Heavy oil production is another operation which often can benefit from the use of VIT or an insulating annular fluid or both. In heavy oil production, a high-pressure steam or hot water is injected into the well and the oil reservoir to heat the fluids in the reservoir, causing a thermal expansion of the crude oil, an increase in reservoir pressure and a decrease of the oil's viscosity. In this process, damage to the well casing may occur when heat is transferred through the annulus between the well tubing and the casing. The resulting thermal expansion of the casing can break the bond between the casing and the surrounding cement, causing leakage. Accordingly, an insulating medium such as VIT or IAF or a combination of the two may be used to insulate or to help insulate the well tubing. The VIT or IAF also reduce heat loss and save on the energy requirements in steam flooding.

In addition to steam injection processes and operations which require production through a permafrost layer, subsea fields—especially, subsea fields in deep water, 1,500 to more than 6,000 feet deep—require specially designed systems which typically require VIT or IAF or a combination of the two. For example, a subsea oil reservoir temperature may be between about 120° F. and 250° F., while the temperature of the water through which the oil must be conveyed is often as low as 32° F. to 50° F. Conveying the high temperature oil through such a low temperature environment can result in oil temperature reduction and consequently the separation of the oils into various hydrocarbon fractions and the deposition of paraffins, waxes, asphaltenes, and gas hydrates. The agglomeration of these oil constituents can cause blocking or restriction of the wellbore, resulting in significant reduction or even catastrophic failure of the production operation.

To meet the above-discussed insulating demands, a variety of packer fluids have been developed. For example, U.S. Pat. No. 3,613,792 describes an early method of insulating wellbores. In the U.S. Pat. No. 3,613,792 patent, simple fluids and solids are used as the insulating medium. U.S. Pat. No. 4,258,791 improves on these insulating materials by disclosing an oleaginous liquid such as topped crude oils, gas oils, kerosene, diesel fluids, heavy alkylates, fractions of heavy alkylates and the like in combination with an aqueous phase, lime, and a polymeric material. U.S. Pat. No. 4,528,104 teaches a packer fluid comprised of an oleaginous liquid such as diesel oil, kerosene, fuel oil, lubricating oil fractions, heavy naphtha and the like in combination with an organophillic clay gellant and a clay dispersant such as a polar organic compound and a polyfunctional amino silane. U.S. Pat. No. 4,877,542 teaches a thermal insulator fluid consisting of a heavy mineral oil as the major liquid portion, a light oil as a minor liquid portion, a smectite-type clay, calcium oxide and hydrated amorphous sodium silicate. U.S. Pat. No. 5,290,768 teaches a thixotropic composition containing ethylene glycol and welan gum. The above-discussed patents are herein incorporated by reference.

Although many of the above-described packer fluids function adequately, they fail to meet industrial and governmental concerns for the environment. Particularly, many of the constituents of the above-described packer fluids are unacceptable from an environmental standpoint and are often prohibited for use by government regulation. For example, the mineral oils and heavy crude oils required by several of the above-discussed patents are not permitted for use in areas such as the Gulf of Mexico.

Further attempts at providing insulating annular fluids based on fluids having a more acceptable HSE profile are discussed in G.B. Patent 2,367,315 by Vollmer (hereinafter referred to as “Vollmer '315”). Nothing is taught about insulating annular fluids in U.S. Pat. No. 5,304,620 by Holtmyer, et al. (hereinafter referred to as “Holtmyer '620”), U.S. Pat. No. 5,439,057 by Weaver, et al. (hereinafter referred to as “Weaver '057”), and U.S. Pat. No. 5,996,694 by Dewprashad, et al. (hereinafter referred to as “Dewprashad '694”). However, Holtmyer '620, Weaver '057, and Dewprashad '694 discuss the viscosification of brines using crosslinked hydroxyethylcellulose derivatives. These patents are hereby incorporated by reference.

Gas hydrates are clathrates (inclusion compounds) in which small hydrocarbon molecules (as well as CO₂, H₂S, and N₂) are trapped in a lattice consisting of water molecules. Clathrate hydrates have structures differing from that of ordinary ice. In clathrate hydrates water molecules form an expanded crystalline structure that traps methane, or other particles. Gas hydrates form exothermically as a consequence of the tendency of water to reorient in the presence of a non-polar solute (typically light hydrocarbon gases such as methane) to stabilize the lattice through, typically, van der Waals interactions while maintaining the hydrogen bonding between the water molecules. Tetrahydrofuran, p-dioxane, CO₂, and H₂S, to name a few other compounds, in addition to the low-molecular-weight hydrocarbons are capable of occupying the interior positions in a clathrate lattice of water molecules and stabilizing the overall structure so that it does not decompose until a relatively substantial increase in temperature or decrease in pressure occurs or both occur.

Gas hydrates form at elevated pressures and at temperatures much higher than the freezing point of water. They can be stable or meta-stable over broad ranges of pressure and temperature. Gas hydrates are stable at combinations of temperature and pressure found in onshore arctic regions and beneath the sea floor in water depths greater than approximately 1,500 feet (500 meters). Changes in either the temperature or the pressure can cause these hydrates to melt but often the temperatures required for such melting is greater than those required for the melting of ice.

Accordingly, there exists a continuing need for development of production techniques for recovering hydrocarbons from reservoirs wherein there is a need to limit the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string.

SUMMARY OF INVENTION

In one aspect, the present invention relates to a proactive approach to limiting the transfer of heat and to limiting the consequences of the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string in ice-laden environments such as those in permafrost areas. In this aspect, the present invention teaches the deployment of cold hydrate-forming fluids into the external ice-laden environment near the production string. If the transfer of heat leads to the melting of some of this ice, the previously deployed cold hydrate-forming fluids will convert the melt-water into hydrate form. The melting point of the hydrates will typically be much higher than that of ice, so subsequent melting will be diminished or eliminated. Additionally, the thermal conductance of melt-water is higher than those of ice or hydrate; consequently, the elimination of melt-water limits the transfer of heat subsequently.

In a closely related aspect of the present invention, when cold, often super-cooled, high pressure water exists in the vicinity of an iceberg or behind an ice dam, the deployment of cold hydrate-forming fluids can reduce or eliminate the cold liquid water by converting it into hydrate form. Often the super-cooled, high pressure water flows beneath or in the lower parts of an iceberg and the friction of flow through this environment leads to heating and further melting. By arresting the flow upon the solidification of this water into hydrate form, this heating mechanism is reduced or eliminated and the subsequent further melting is minimized. Additionally, the melting point of the thus formed hydrate will typically be higher than that of ice, so subsequent melting will be rendered less likely. This aspect of the present invention differs from the other aspects in that the production of relatively hot fluids is optional and indeed need not necessarily be involved.

In other aspects of the present invention, either passive or active mechanical means are deployed to limit the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string. In the passive mechanical approach, a weir or a series of weirs is deployed in a low-pressure-gas-filled annulus so that any liquid or solid material that could condense on the outer, cooler portions of the annulus would be trapped in the weir and held so that the condensable (i.e., vaporizable) material is sequestered so as to prevent the establishment of even an only moderately effective “heat pipe” or thermosyphon in the annulus and simultaneously to disrupt the patterns of convection in the gas that can lead to convective heat loss.

In a preferred embodiment of another aspect of the present invention, the invention relates to methods for deploying in an annulus of a well at least one active system. This active system operates as a vapor-compression refrigerator/heat pump cycle, although it will be obvious to those skilled in the relevant art that either a vapor-absorption or a gas cycle device could be used as well. High pressure, high temperature refrigerant vapor leaves the compressor located at the top of the well and enters the top of an annulus located more immediately adjacent to the relatively hot production tubing. These hot vapors move downward in this annulus giving up heat to any surfaces which are at lower temperature. Because the hot vapor is held at high pressure, when the wall temperature reaches the value corresponding to the liquid-vapor equilibrium at that pressure, the hot vapor begins to condense giving up more heat, the latent heat of condensation. The local temperature remains constant at this value as long as both phases are present and the local pressure is constant. The condensed liquid runs down the tubing walls and collects in the space above the annulus packer. There it enters one or more expansion elements which throttle the flow of liquid refrigerant from the more inner annulus condenser element to a more outer annulus evaporator element. The inner and outer annuli may be insulated from each other conventionally or by an intermediate annulus filled with low pressure gas and fitted with weirs as described earlier. The low pressure gas can be the same as or different from the low pressure gas contained in the more outer annulus. The more outer annulus which serves as the evaporator element of the vapor-compression refrigerator/heat pump cycle is connected to the intake of the compressor and is thereby maintained at lower pressure than the more inner annulus. In this low pressure region the liquid refrigerant evaporates taking up heat from the exposed tubing walls. Cold liquid wets the walls and runs toward the bottom of the more outer annulus. As it evaporates, its cold vapors rise to the top of the well and, after passing through a conditioner used to remove water or other contaminants, enter the compressor to begin another cycle.

The present application also describes a process for injecting cold hydrate-forming fluids into the external ice-laden environment of an oil, gas condensate, or gas well in permafrost area, allowing the hydrate forming fluids to mix with any melt-water that may be present or that may subsequently form due to the loss of heat from the oil, gas condensate, or gas well so that the mixture of cold hydrate-forming fluids and melt-water can form solid hydrate. In this process, the hydrate-forming fluids preferably include at least one of tetrahydrofuran, p-dioxane, CO₂, H₂S, and the low-molecular-weight hydrocarbons. In another embodiment of this process, the hydrate-forming fluids include at least one of tetrahydrofuran, p-dioxane, CO₂, H₂S.

There is also described a process for injecting cold hydrate-forming fluids into the melt-water found in the vicinity of a glacier, ice dam, or other naturally occurring ice formation, allowing the hydrate forming fluids to mix with the melt-water that may be present or that may subsequently form due to further melting of the ice in the vicinity of the glacier, ice dam, or other naturally occurring ice formation so that the mixture of cold hydrate-forming fluids and melt-water can form solid hydrate. In this process, the hydrate-forming fluids preferably include at least one of tetrahydrofuran, p-dioxane, CO₂, H₂S, and the low-molecular-weight hydrocarbons. In another embodiment of this process, the hydrate-forming fluids include at least one of tetrahydrofuran, p-dioxane, CO₂, H₂S.

There is further described herein an apparatus comprising at least one weir deployed in at least one gas-filled or partially evacuated annulus of an oil, gas condensate, or gas well configured in such a way as to allow any condensable or subsequently vaporizable material to be collected and sequestered. There is also described a process of employing this apparatus so as to prevent the establishment of even an only moderately effective “heat pipe” or thermosyphon in the annulus. There is further described a process of employing this apparatus so as to disrupt the patterns of convection in the gas in the annulus that can lead to convective heat loss.

This application also discloses a method of deploying in at least one annulus of an oil, gas condensate, or gas well at least one vapor-compression refrigerator/heat pump cycle.

This application further discloses a method of deploying in at least one annulus of an oil, gas condensate, or gas well at least one vapor-absorption device.

There is also disclosed a method of deploying in at least one annulus of an oil, gas condensate, or gas well at least one gas cycle device.

Methods and equipment are provided (1) for controlling temperatures in the environments of oil, gas condensate, or gas wells and (2) for reducing the melting of glaciers and ice dams through the deployment of hydrate-forming substances. The environmental temperature control includes both (1a) active and (1b) passive methods or a combination of the two. The active method involves employing a vapor-compression refrigerator/heat pump cycle in an annulus lying between the relatively hot production string and the relatively cold outer pipe. In this method, heat is pumped away from the relatively cold outer pipe so that the ΔT becomes small there; and heat is pumped toward the relatively hot production string so that the ΔT becomes small there as well.

The passive methods include: deploying cold hydrate-forming fluids into the external ice-laden environment of an oil, gas condensate, or gas well in a permafrost area and allowing those hydrate forming fluids to mix with any melt-water that may be present or that may subsequently form due to the loss of heat from the oil, gas condensate, or gas well. The mixture of the hydrate forming fluids and the melt-water will set up into a solid having a much higher melting point and a much lower thermal conductivity than those of ice. Similar deployment of cold hydrate-forming fluids can reduce or eliminate the melting of glaciers and ice darns.

Other passive methods include: deploying a low-pressure-gas-filled weir in an annulus lying between the relatively hot production string and the relatively cold outer pipe. The low-pressure gas is characterized by very low conductive heat loss and in combination with the weir, which acts as a baffle, by very low convective heat loss. Additionally, the weir will trap any condensate that happens to occur in the low-pressure gas, causing any heat loss due to condensation to be reduced to a one-time only occurrence.

It is believed that one or a combination of these methods can augment or replace the two strategies known in the prior art for diminishing the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string—the deployment of vacuum insulated tubulars (VITs) and insulating packer fluids (IPFs).

The applications for this technology include situations where the loss of heat from the produced fluids leads to an increase in viscosity of the fluid or the deposition of wax, asphaltenes, or hydrates in the production string to the point that fluid production is seriously diminished or shut off. Other applications for this technology include situations where the loss of heat from the produced fluids leads to an undesirable increase in temperature in the external environment. Wells in permafrost areas can lose mechanical integrity when there is an increase in temperature in the external environment which leads to melting of the ice. In the near-mudline environment of wells in deepwater areas, extreme pressure build-up can occur in outer (trapped) annuli, leading to the imposition of extreme pressure on the production string and a catastrophic pipe collapse. These disastrous outcomes can be significantly mitigated or eliminated by the use of technology in accordance with the present invention. Extremely deep wells where the bottom-hole temperature is high are characterized in deepwater or permafrost environments by especially large ΔTs across the annulus. For these wells, a combination of this new technology along with the conventional VITs and IPFs may be required.

Another embodiment discloses a method for mitigating the ice melting effects of heat transfer caused by the production of relatively hot fluids from an oil, gas condensate or gas well in a permafrost area, comprising the steps of: (a) introducing one or more cold hydrate-forming fluids into an external ice-laden environment proximate the well in the area of such heat transfer; and (b) permitting said one or more hydrate forming fluids to mix with any melt-water that may be present in said environment or that may subsequently form in said environment due to the loss of heat from the well so that said mixture of said one or more cold hydrate-forming fluids and melt-water form solid hydrates. In this process hydrate-forming fluids can be selected from the group consisting of tetrahydrofuran, p-dioxane, CO₂, H₂S, and the low-molecular-weight hydrocarbons. In another embodiment, the one or more hydrate-forming fluids include at least one of tetrahydrofuran, p-dioxane, CO₂, and H₂S.

Another embodiment discloses a process for reducing ice melt in the vicinity of a glacier, ice dam, or other naturally occurring ice formation comprising the steps of: (a) locating one or more zones in the vicinity of said glacier, ice dam, or other naturally occurring ice formation where melt-water exists or is likely to exist; (b) introducing at least one cold hydrate-forming fluid into said one or more zones; and (c) permitting said at least one hydrate forming fluid to mix with any melt-water that may be present in said one or more zones or that may subsequently form in said one or more zones so that said mixture of said at least one cold hydrate-forming fluids and melt-water form solid hydrates. In this process the hydrate-forming fluid may be selected from the group consisting of tetrahydrofuran, p-dioxane, CO₂, H₂S, and the low-molecular-weight hydrocarbons. In another embodiment, the hydrate-forming fluids include at least one of tetrahydrofuran, p-dioxane, CO₂, and H₂S.

There is also disclosed an apparatus for collecting liquid formed from condensable or vaporizable materials in a low-pressure-gas-filled or partially evacuated annulus of an oil, gas condensate, or gas well comprising: (a) an inner tubular member having an exterior wall surface; (b) an outer tubular member axially surrounding said inner tubular member and having an interior wall surface; (c) an annular space created between said inner tubular exterior wall surface and said outer tubular interior wall surface; and (d) one or more weir members attached to said outer tubular interior wall surface, said one or more weir members comprising a bottom end having a floor member, one or more concentrically spaced apart annular wall members attached to said floor member, an open top end, and one or more fluid collection chambers created in the space between said one or more concentrically spaced apart annular wall members, said outer tubular member intended to be installed in said well such that said top end of said weir is oriented in a generally upward direction within said well so that annular liquid formed on said outer tubular member interior wall surface is permitted to flow generally downwardly along said outer tubular member interior wall surface and into said one or more fluid collection chambers.

There is further disclosed a method of well thermal management in a low-pressure-gas-filled or partially evacuated annulus of an oil, gas condensate, or gas well comprising the steps of: (a) placing one or more weirs within said annulus and (b) collecting and sequestering said formed annular fluid. In this embodiment, the annulus is generally defined as having an inner tubular member having an exterior wall surface; an outer tubular member axially surrounding the inner tubular member and having an interior wall surface; and an annular space created between the inner tubular exterior wall surface and the outer tubular interior wall surface; the one or more weir members being attached to the outer tubular interior wall surface, the one or more weir members comprising a bottom end having a floor member, one or more concentrically spaced apart annular wall members attached to the floor member, an open top end, and one or more fluid collection chambers created in the space between the one or more concentrically spaced apart annular wall members. In this embodiment, the outer tubular member is installed in the well such that said top end of the weir is oriented in a generally upward direction within the well so that annular liquid formed on the outer tubular member interior wall surface is permitted to flow generally downwardly along the outer tubular member interior wall surface and into the one or more fluid collection chambers. This method can be used to prevent establishment of an effective heat pipe or thermosyphon. This method can also be used to disrupt the patterns of convection in the gas present in said annulus.

There is also described an expansion control coupler for use in oilfield annular tubing comprising: (a) a cylindrical tubing connector body having an exterior surface and an interior surface, a central body section having an upper end and a lower end displaced between two threaded connector sections capable of receiving threaded tubing, and one or more liquid outlet holes proximate the upper end creating a conduit between said connector body interior surface and said connector body exterior surface; and (b) a cylindrical capillary expansion groove insert fitted within the central body section. This cylindrical capillary expansion groove inserted further comprises an outer annular wall member having an outer face and an inner face and an upper end and a lower end; an annular liquid collection dam wall member having an outer dam face and an inner dam face and a dam upper end and dam lower end, the dam being connected at its bottom end to said bottom end of the outer annular wall member such that the annular dam wall member and the outer annular wall member exist in a substantially spaced-apart coaxial relationship; a liquid collection zone created by the space between the annular dam member and the outer annular wall member; a lower groove in the exterior surface of the outer annular wall member its proximate its lower end; an upper groove in the exterior surface of the outer annular wall member proximate its upper end; one or more drainage holes in the lower groove to permit fluid communication between the liquid collection zone and the lower groove; and one or more capillary grooves located in the outer face of the outer annular wall member connecting between the lower groove and the upper groove to permit fluid communication between the lower groove and the upper groove. In this embodiment, the liquid outlet holes in the central body upper end being positioned to register with the upper groove of the outer annular wall member, and the coupler provided fluid communication between the liquid collection zone and the connector body exterior surface.

The present application also discloses a well thermal management system for controlling fluid temperatures in fluids produced in oilfield well production tubing comprising: (a) a well installation having a production tubing string producing fluids from a desired region of a subsurface formation to the surface; (b) a first annulus tubing section axially surrounding at least a portion of the production tubing string, the first annulus having a top end located at the surface of the well installation and a bottom end located at a desired depth along the tubing string, the first annulus tubing section having an inside tubing wall surface and an outside tubing wall surface; (c) a second annulus tubing section axially surrounding at least a portion of the first annular tubing section to the surface, the second annulus having a top end located at the surface of the well installation and a bottom end located at a desired depth along the first annulus; (d) a refrigeration system having an outlet in fluid communication with the first annulus top end for introducing into the first annulus one or more desired refrigerants at a desired temperature(s) and pressure(s), and an inlet in fluid communication with the second annulus top end; (e) one or more zones for collecting liquid formed on the inside tubing wall surface of the first annulus; (f) one or more expansion control elements creating fluid communication between the first annulus and the second annulus at desired depths to permit the passage of the one or more refrigerants from the first annulus to said second annulus, the one or more expansion control elements being located proximate the one or more liquid collection zones; and (g) conduit for directing fluid flow from the second annulus back to the inlet of said refrigeration system. In this embodiment, the first and second annulus and the refrigeration system are tied together as a closed system. The embodiment of this system can employ a refrigeration system selected from the group consisting of: vapor-compression refrigerator/heat pump cycle systems, vapor-absorption systems and gas cycle systems. In one embodiment, the refrigeration system is a vapor-compression refrigerator/heat pump cycle system using a compressor for introducing one or more of desired refrigerants, and further comprising a pressure regulation and monitoring system. In another embodiment, the one or more expansion control elements are selected from the group consisting of thermostatic expansion valves and simple capillary tubes. In another embodiment, a liquid collection zone is defined as the region immediately above the bottom end of the first annulus. The liquid collection zones may further comprise one or more liquid collection systems each comprising a concentric extended lip attached to the first annulus inside tubing wall surface at desired depths and wherein at least one of the one or more expansion control elements is placed in the one or more liquid collection systems to permit passage of fluid collected from the first annulus to the second annulus.

There is further disclosed a method for controlling fluid temperatures in fluids being produced to a surface oilfield well installation from production tubing located in desired regions of a subsurface formation comprising the steps of: (a) providing a first annulus tubing section axially surrounding at least a portion of the production tubing string, the first annulus having a top end located at the surface of the well installation and a bottom end located at a desired depth along the tubing string, the first annulus tubing section having an inside tubing wall surface and an outside tubing wall surface; (b) providing a second annulus tubing section axially surrounding at least a portion of the first annular tubing section to the surface, the second annulus having a top end located at the surface of the well installation and a bottom end located at a desired depth along the first annulus; (c) providing a refrigeration system having an outlet in fluid communication with the first annulus top end for introducing into the first annulus one or more desired refrigerants at a desired temperature(s) and pressure(s), and an inlet in fluid communication with the second annulus top end; (d) providing at desired locations within the first annulus one or more zones for collecting liquid formed on the inside tubing wall surface of the first annulus; (e) providing one or more expansion control elements creating fluid communication between the first annulus and the second annulus at desired depths to permit the passage of the one or more refrigerants from the first annulus to the second annulus, the one or more expansion control elements being located proximate the one or more liquid collection zones; (f) providing conduit for directing fluid flow from the second annulus back to the inlet of the refrigeration system; (g) operating the first and second annulus and the refrigeration system as a closed system; (h) directing a refrigerant vapor into the top end of the first annulus; (i) collecting condensed liquid in said one or more liquid collection zones; (j) directing the collected fluids through eh one or more expansion control elements into the second annulus, and (k) directing the fluids in the second annulus back to the inlet of the refrigeration system. In one embodiment of this method, the first annulus is maintained at high temperature and high vapor pressure while substantially simultaneously maintaining the second annulus at low temperature and low vapor pressure. The refrigeration system can be selected from the group consisting of: vapor-compression refrigerator/heat pump cycle systems, vapor-absorption systems and gas cycle systems. The refrigeration system can be a vapor-compression refrigerator/heat pump cycle system using a compressor for introducing one or more of the desired refrigerants, and further comprising a pressure regulation and monitoring system. The expansion control elements can be thermostatic expansion valves, simple capillary tubes and the like. Other aspects and advantages of the invention will be apparent from the following detailed description and the appended claims.

BRIEF SUMMARY OF DRAWINGS

The accompanying drawings, which are incorporated in and constitute a part of the specification, illustrate preferred embodiments of the invention. These drawings, together with the general description of the invention given above and the detailed description of the preferred embodiments given below, serve to explain the principles of the invention.

FIG. 1 shows a schematic diagram of a well thermal management system with according to the present invention.

FIG. 2 presents a schematic diagram of a well installation using the present invention to control the temperatures of the fluid in the production tubing and surrounding medium.

FIG. 3 presents a semi-log plot depicting the vapor pressure of propane vs. temperature to illustrate the coexistence curve for propane's liquid/vapor equilibrium.

FIG. 4 presents a graph showing A annulus temperature profile with T_(o)=100° F.

FIG. 5 presents a graph showing A annulus pressure profile when P_(o)=189 psi.

FIG. 6 presents a graph showing B annulus temperature profile with Tmax=32° F. and P_(o)=1 bar.

FIG. 7 presents a graph showing B annulus pressure profile when P_(o)=15.5 psi.

FIG. 8 presents a graph showing B annulus temperature profile with Tmax=32° F. and P_(o)=½ bar.

FIG. 9 presents a graph showing B annulus pressure profile when P_(o)=7.3 psi.

FIG. 10 shows a schematic diagram of a well thermal management system with distributed evaporation elements according to the present invention.

FIG. 11 illustrates a cut-away view of a tubing connector with liquid collector and multiple expansion control elements according to an embodiment of the present invention.

FIG. 12 illustrates a side view of a single capillary expansion groove insert according to one embodiment of the present invention.

FIG. 13 illustrates a side view of a multi-capillary expansion groove insert according to another embodiment of the present invention.

FIG. 14 illustrates a perspective view of a multi-capillary expansion groove insert according to another embodiment of the present invention.

FIG. 15 illustrates a cut-away view of a refrigerant expansion control tube coupler according to the present invention.

DETAILED DESCRIPTION OF INVENTION

In one aspect, the present invention relates to ice-laden environments such as those in permafrost areas where a proactive approach is taught herein (1) limiting the consequences of the transfer of heat from the relatively hot produced fluids into the ice in the environment surrounding the production string, impeding the melting of ice, and thereby (2) limiting the transfer of heat. In this aspect, the present invention teaches the deployment of cold hydrate-forming fluids into the external ice-laden environment near the production string. If subsequently the transfer of heat leads to the melting of some of this ice, the previously deployed cold hydrate-forming fluids will convert the melt-water into hydrate form. The melting point of the hydrates will typically be much higher than that of ice, so subsequent melting will be diminished or eliminated. Additionally, the thermal conductance of melt-water is higher than those of ice or hydrate; consequently, the elimination of melt-water limits the transfer of heat subsequently.

Examples of suitable substances to deploy in this fashion include tetrahydrofuran, p-dioxane, CO₂, H₂S, and the low-molecular-weight hydrocarbons. The first four of these are capable of occupying the interior positions in the clathrate lattice of water molecules and stabilizing the overall structure at conditions under which the partial pressure of the tetrahydrofuran, p-dioxane, CO₂, and H₂S, respectively, is relatively low compared with that required for the formation of hydrates from alternatives such as N₂, O₂, and the low-molecular-weight hydrocarbons. Accordingly, such substances as, for example, tetrahydrofuran, p-dioxane, CO₂, and H₂S are preferred substances to deploy in permafrost areas to convert the mixture of melting ice and cold hydrate-forming fluids into solid hydrate form. Because these preferred substances form hydrates at relatively low partial pressures of the hydrate-forming fluid, there would have to occur, subsequently to the formation of solid hydrates, a marked increase in temperature or decrease in pressure or both before the solid hydrates would decompose. During the period when solid hydrates or ice are present to the exclusion of melt-water, the conductance of heat from any wellbore deployed in this vicinity would be reduced because hydrates and ice have a lower conductance of heat than liquid water. Solid hydrates and ice are very unlikely to be subject to sufficient shear stress to cause them to go into convection whereas melt-water is relatively easy to force into convection. Accordingly, convective heat loss will virtually always be absent when no melt-water and only hydrates or ice are present. Melt-water, on the other hand, can easily be forced into convection and the literature even documents cases wherein similar fluids go into turbulent flow in annuli of oil and gas wells. The onset of turbulent-flow-induced convective heat loss can increase the thermal conductance to values 100 to 300 times as large as the thermal conductivity alone.

A closely related aspect of the present invention includes embodiments to reduce the melting of glaciers and ice dams that hold back glacial melt-water. In summer in some locations in Greenland, for example, small pools of melt-water sometimes form on the upper surfaces of glaciers. The melt-water may channel through a crack in the ice or through a channel made by escaping air previously entrapped within the glacier. When this occurs, cold, often super-cooled, high pressure water can be found flowing through and below the glacier or behind, through, and below the ice dam. The friction of this flowing liquid through the ice can lead to further melting. The deployment of cold hydrate-forming fluids can reduce or eliminate the cold liquid water by converting it into hydrate form. Additionally, the melting point of the thus formed hydrate will typically be higher than that of ice, so subsequent melting will be rendered less likely. Furthermore, much of the thus formed solid hydrate will reside deep within the glacier where the pressure is relatively high, making it yet less likely that the hydrate can subsequently decompose.

In one embodiment of this aspect of the present invention, a wellbore can be constructed for use in deployment of the hydrate forming fluid; but in other embodiments of this aspect of the present invention no wellbore need be present. Accordingly this aspect of the present invention differs from the other aspects of the present invention in that the production of relatively hot fluids need not be involved.

In other aspects of the present invention, passive mechanical means are deployed to limit the transfer of heat from the relatively hot produced fluids into the environment surrounding the production string. In this approach, a weir 15 or a series of weirs as illustrated in FIG. 1 is deployed in a low-pressure-gas-filled annulus A so that any liquid or solid material that could condense on the outer, cooler portions of the annulus A (e.g., here, the inner walls 10 a of the pipe joint 10) would be trapped in the weir 15 and held so that the condensable (i.e., vaporizable) material is sequestered so as to prevent the establishment of even an only moderately effective “heat pipe” or thermosyphon in the annulus and simultaneously to disrupt the patterns of convection in the gas that can lead to convective heat loss. In this particular example, the annulus A is the area between an inner tubular member (here the production tubing 100) having an exterior wall surface 100 a and an outer tubular member (here pipe joint 10) axially surrounding said inner tubular member 100 and having an interior wall surface 10 a. The annulus is the annular space A created between the inner tubular exterior wall surface 100 a and the outer tubular interior wall surface 10 a.

In one embodiment, weir member 15 comprises a bottom end 15 a having a floor member 15 b that is attached to, and extending radially away from, the pipe joint inner wall 10 a. The weir also comprises one or more concentrically spaced apart annular wall members or fins 15 c attached to said floor member 15 b that extend upwardly over a desired fin height 15 d towards the top region 15 e of weir 15. The top region 15 e of the weir 15 is open to thereby create one or more fluid collection or sequestration chambers 15 f created in the space between each of the one or more concentrically spaced apart annular wall members 15 c. As will be apparent from the design, the pipe joint 10 (i.e., the outer tubular member defining annulus A), is intended to be installed in the well such that the top end 15 e of the weir 15 is oriented in a generally upward direction within said well so that annular liquid formed on outer tubular member interior wall surface 10 a is permitted to gravitationally flow generally downwardly along the outer tubular member interior wall surface 10 a and into the one or more fluid collection chambers 15 f of the weir 15. Deploying one or more weirs within a desired annulus provides a method or well thermal management, particularly applicable in a low-pressure-gas-filled or partially evacuated annulus of an oil, gas condensate or gas well. As will be understood by those having the benefit of this disclosure, each tubing joint 10 in the well could be outfitted with one or more weirs, or the tubing string in the well could deploy weirs only on selected pipe joints.

A majority of annular heat loss is due to (1) combinations of evaporation from relatively hot regions and condensation onto relatively cold regions, (2) convection and (3) conduction. In the embodiment of the present invention involving a low-pressure-gas-filled annulus with one or more weirs 15 as illustrated in FIG. 1, the purpose of the weirs 15 is to trap any material that is condensed and hold it in a relatively cold region of the gas-filled annulus so that these combinations of evaporation and condensation are interdicted and arrested. The figure shows an example of a single joint of pipe 10 that can be threaded at each end and joined to other such joints of pipe or to conventional pipe joints lacking the weirs 15. The figure also shows a segment of an inner largely concentric pipe 100 that, together with the outer pipe 10 to which the weirs 15 are attached, define the annulus A wherein the low pressure gas is deployed. By interdicting the transport of the condensable material and holding it in a relatively cold region, the opportunity for it subsequently to move to a warm region and evaporate is interdicted. Thus the evaporation and condensation cycle is reduced or eliminated as a contributor to the heat transfer across the low-pressure-gas-filled annulus even if the gas is or becomes contaminated with moisture, for example. Heat loss due to convection can be arrested or substantially diminished in liquids by increased viscosities of the liquids; however, doing the same with gases is much more difficult to bring about. Nevertheless, the weirs 15 deployed in this embodiment of the invention serve at least to disrupt somewhat the convection patterns in the low pressure gas and thereby to reduce the convective heat loss. Heat loss due to thermal conductivity needs to be controlled by proper selection of fluids. Suitable low pressure gases useful in accordance with this embodiment of the present invention include such gases as, for example, N₂ and the low molecular weight hydrocarbons and mixtures thereof. It should be noted that in an entirely different embodiment of the present invention, some of these same substances such as, for example, low molecular weight hydrocarbons and mixtures thereof, can also be used as working fluids in an active vapor-compression refrigerator/heat pump cycle.

In yet other aspects of the present invention, passive mechanical means as discussed earlier are augmented by or replaced by at least one active system. In a preferred embodiment this active system operates as a vapor-compression refrigerator/heat pump cycle, although it will be obvious to those skilled in the relevant art that either a vapor-absorption or a gas cycle device could be used as well. The basic concept of the invention is illustrated schematically in the drawing of FIG. 2, which shows a well installation 20 using the invention to control the temperatures of the fluid in the production tubing 100 and in the surrounding medium 21. As depicted, the production string 100 is located to permit production from the producing formation 20 b

High pressure, high temperature refrigerant vapor leaves the outlet 22 a of compressor 22 located at the top of the well 20 a and enters the top of the A annulus, immediately adjacent to the production tubing 100. These hot vapors move downward in the A annulus giving up heat to any surfaces which are at lower temperature. When the wall (A-1) temperature reaches the value corresponding to the liquid-vapor equilibrium at the local pressure, the hot vapor begins to condense giving up more heat, the latent heat of condensation. The local temperature remains constant at this value as long as both phases are present and the local pressure is constant. The condensed liquid runs down the A annulus tubing walls A-1 and collects in the space or liquid collection zone 24 above the A annulus packer 25. There it enters one or more expansion elements 30 which throttle the flow of liquid refrigerant from the A annulus condenser to the B annulus evaporator. The B annulus is connected to the intake 22 b of the compressor 22 and is thereby maintained at lower pressure than the A annulus. In this low pressure region the liquid refrigerant evaporates taking up heat from the exposed tubing walls. Cold liquid wets the B annulus walls B-1 and runs toward the bottom of the B annulus where it could collect in the region or liquid collection zone 26 above the B annulus packer 27. As it evaporates its cold vapors rise to the top of the well and after passing through a refrigerant conditioner 23 used to remove water or other contaminants enter the compressor 22 to begin another cycle.

The expansion control element(s) 30 may be based on any of the well known devices used in refrigeration cycles, such as thermostatic expansion valves or simple capillary tubes. For illustrative purposes, the expansion control element 30 in FIG. 2 is shown to be a single capillary tube. In the drawing the directions of flow of refrigerant fluids are shown by solid arrows 28 and of heat by dashed arrows 29. Pressure gauges 31 and 32 measure pressures in the A and B annuli, respectively, at the top of the well 20 a. Although some heat flows from the A annulus to the B annulus through the separating tubing wall A-1, this wall is provided with sufficient insulation (not shown) to assure that the major cooling promoted by phase change in the evaporator is of the outer surroundings rather than of material in the A annulus.

In its simplest configuration as shown in FIG. 2 and described above, this invention operates to maintain simultaneously two separate liquid/vapor equilibria, one at high temperature and high vapor pressure in the A annulus, and one at low temperature and low vapor pressure in the B annulus of a well. Unlike conventional heat pump installations where the refrigerant lines are confined to a single elevation or are distributed over regions of only modest vertical heads, the installations in which this invention will be used involve extreme vertical runs between the resource reservoirs 20 b and the surface production facilities. The concomitant effects must be considered in modeling the heat pump performance. Performance details will depend on the specific refrigerant used, its molecular mass, its phase behavior, and its thermophysical properties (fluid densities, heat capacities, heat of vaporization). How these factors influence performance can be illustrated simply by selecting a potential refrigerant and using simplified models of its barometric pressure variation and its heat of vaporization.

For this illustration consider propane (C₃H₈) used as the refrigerant fluid. The coexistence curve for propane's liquid/vapor equilibrium is represented on the semi-log plot of FIG. 3.

The coexistence line spans wide ranges of temperature and pressure. Limiting our consideration to pressures higher than about 1 bar, the temperature span is 231° K-370° K (−44° C.-206° C.) while the corresponding pressure span is 1 bar-42.5 bar (15 psi-616 psi). If the two-phase equilibrium was maintained in both the A and B annuli over their entire length, the pressure and temperature would vary vertically in accordance with the barometric formula and the Clapeyron equation.

$\begin{matrix} {{{dP} = {{- \rho}\; {gdh}}}{{Barometric}\mspace{14mu} {formula}}} & (1) \\ {{{dP} = {\frac{\Delta \; H_{vap}}{T\; \Delta \; V}{dT}}}{{Clapeyron}\mspace{14mu} {Equation}}} & (2) \end{matrix}$

Where ρ is the vapor density, g the acceleration of gravity, h the elevation in the gravitational field, ΔHvap the heat of vaporization of the liquid, and ΔV the difference in volume of the vapor and liquid phases. Assuming the vapor to be an ideal gas and the heat of vaporization to be independent of temperature, these equations become:

$\begin{matrix} {{dP} \approx {{- \frac{PM}{RT}}{gdh}}} & (3) \\ {{dP} \approx {\frac{P\; \Delta \; H}{{RT}^{2}}{dT}}} & (4) \end{matrix}$

Equating the right hand sides of Equations 3 and 4 and integrating from T_(o) and h_(o) at the surface and T and h at depth D=h_(o)−h gives:

$\begin{matrix} {T \approx {T_{o}^{\frac{M_{g}D}{\Delta \; H}}}} & (5) \end{matrix}$

Taking M=0.044 kg/mol and ΔHvap=18.75 kj/mol for propane and g=9.806 m s−2, this becomes:

T_(D)≈T_(o)*e^(2.5×10) ⁻⁵ ^(m) ⁻¹ ^(*D)   (6)

With D the depth in meters. The equilibrium vapor pressure corresponding to the temperature at depth D obtained by integrating Equation 4 is:

$\begin{matrix} {P_{D} \approx {P_{o}^{\frac{\Delta \; H}{R}{\lbrack{\frac{1}{T_{o}} - \frac{1}{T_{D}}}\rbrack}}}} & (7) \end{matrix}$

If, for example, it was desired to maintain the temperature of the A annulus to temperatures not lower than 100° F. (311° K), FIG. 3 shows that it would be sufficient, using propane as refrigerant, to inject the compressed gas into the top of the A annulus at 13 bar or 189 psi. Equations 6 and 7 show that both temperature and pressure rise with increasing depth. The high pressure-temperature limit of two phase stability in the A annulus is the critical point shown on the plot of FIG. 3. Plots of Equations 6 and 7 showing the variations of temperature and pressure in the A annulus with depth when T_(o) and P_(o) are 100° F. and 189 psi respectively are shown in FIGS. 4 and 5.

These graphs show that, subject to the assumed model, maintaining the temperature of the A annulus and consequently the production tubing and its contents to values not lower than 100° F. by means of propane liquid/vapor equilibrium can be applied to wells as deep as 7700 m or 4.78 miles. At greater depths the propane in the A annulus would be supercritical. Its temperature and pressure would exceed the critical values (206° F. and 612 psi). Refrigeration would continue to occur when the supercritical fluid expands into the low pressure of the B annulus, so deeper wells can be maintained by the same treatment. The ultimate depth limit of the invention is determined by the refrigeration requirements of the A annulus. For example if the maximum temperature in the B annulus was set to 32° F. and the intake pressure at the compressor was maintained at 1 bar (14.5 psi), The temperature and pressure profiles of the B annulus would correspond to those shown in FIGS. 6 and 7.

For these conditions (P_(o)=1 bar and T≦32° F.), the B annulus depth could be no more than 7400 meters. If we retain the requirement that T≦32° F. but lower the compressor intake pressure to 0.5 bar, the operating range is extended as the plots show in FIGS. 8 and 9.

For these conditions the operating depth for the B annulus is 10,000 meters or 6.2 miles.

DESCRIPTION OF AN IMPROVED VERSION OF THIS ASPECT OF THE INVENTION

The preferred embodiment described above features expansion control element(s) located only at the bottom of the A annulus. More efficient heat transfer, especially into the B annulus can be provided by the modification described here. This modification is illustrated schematically in FIG. 10.

The modified well thermal management system includes the features of the basic concept system of FIG. 2 but includes one or more liquid collection sites or zones 24, 24 a with expansion control elements 30 used to throttle the flow of liquid refrigerant condensed on the outer wall A-1 of the A annulus into the low pressure B annulus. FIG. 10 shows one such liquid collector 16 comprised of an extended lip 16 a concentric to the tubing wall A-1 which forms the wall between the A and B annuli forming an annular space or collection zone 24 a into which liquid condensate running down the outer wall A-1 of the A annulus flows. At the bottom of this collector 16 one or more expansion control elements 30 provide conduits for the pressurized liquid to flow into the low pressure B annulus, where it sprays into the rising column of refrigerant vapor adding renewed cooling capacity to this section of the B annulus. In a balanced system similar liquid collectors 16 with expansion elements 30 are distributed in a linear array along the tubing A-1 separating the A and B annuli at spacings which assure that the flow of liquid refrigerant enters the rising column of refrigerant as this column is becoming dry. The added spray of liquid droplets provides sufficient evaporative cooling to maintain the desired refrigeration of the section of B annulus leading to the next higher collector/injector unit.

A natural location for these intermediate collector/injector devices 16 is in the couplings which are necessary to join the individual lengths of tubing needed to make up the entire string. The collector/injector units 16 would be installed in each coupling or in every nth one, as needed, to optimize the thermal management over the entire length of the A and B annuli.

A preferred embodiment of a tubing connector 500 with integral liquid collector insert 400 and multiple expansion elements or channels 414 is shown in section view in FIG. 11.

Referring to FIGS. 11-15, the capillary expansion groove insert 400 is a cylindrical, U-shaped insert which fits tightly or is welded into the central bore of the tubing connector body 500. The substantially U-shaped insert 400 comprises an outer annular wall member 410 having an outer face 410 a and an inner face 410 b, and an upper end 410 c and a lower end 410d; an inner annular wall member or liquid collection dam 420 having an outer dam face 420 a and an inner dam face 420 b and a dam upper end 420 c and dam lower end 420 d, the dam 420 being connected at its bottom end 420 d to the bottom end 410 d of the outer annular wall member 420 to form a trough or liquid volume collection zone 510. As will be understood by those having the benefit of this disclosure, the U-shaped insert could be constructed of a unitary construction, or be fabricated from two parts (i.e., outer cylinder and inner dam) that are fixably attached together by, e.g., threaded connection, welding, gluing or other appropriate method of attachment). The dam 420 can extend to a desired height, here, shown to be about the same height as the outer annular wall member 410, but such height could be varied.

The outer annular wall member 410 also comprises a lower groove 411 in its outer surface proximate its lower end 410 d and an upper groove 412 in its outer surface proximate its upper end 410 c. The outer annular wall member 410 further comprises one or more drainage holes or conduits 413 in the lower groove 411 to permit fluid communication between the liquid collection zone 510 and the lower groove 411. The outer face 410 a of the outer annular wall member 410 is contains one or more capillary grooves 414 connecting between the lower groove 411 and the upper groove 412. In one embodiment, a single capillary groove 414 is wound helically around the outer face 410 a of the outer annular wall member 410 wherein the capillary groove 414 has a first end 415 opening into the lower groove 411 and a second end 416 opening into the upper groove 412 thereby creating a grooved pathway between the lower groove 411 and the upper groove 412. In another embodiment, multiple helical capillary grooves (e.g., 414 a, 414 b, 414 c, 414 d, 414 e, 414 f are wound, in parallel fashion, around the outer face 410 a of the outer annular wall member 410 thereby creating multiple parallel grooved pathways between the lower groove 411 and the upper groove 412.

The capillary expansion groove insert 400 fits tightly or is welded into the central bore of the tubing connector body 500. The tubing connector body 500 has an exterior surface 505 and an interior surface 506 and a central body section 501 having an upper end 502 and a lower end 503 displaced between two threaded connector sections 504. The connector body 500 is modified to contain, at its upper end 502, one or more liquid outlet holes 450 creating a conduit between the connector interior surface 506 and the connector exterior surface 505, and positioned such that, when the capillary expansion groove insert 400 is mounted or otherwise fixably attached into the central bore 501 of the tubing connector body 500, the one or more liquid outlet holes 450 will be aligned with the upper groove 412 of the outer annular wall member 410.

As configured, the refrigerator expansion control tube coupler 500 permits fluid collected in the liquid collection zone 510 to move through drainage holes 413 into lower groove 411, through one or more capillary grooves 414 into upper groove 412, through liquid outlet holes 450 and into the adjacent annular space, e.g., fluid movement from A annulus to B annulus.

Liquid refrigerant condensed on the inner wall A-1 of the higher annulus separator tubing (here the A annulus) flows down this wall A-1 and into the liquid collector or capillary expansion groove insert 400 mounted in the central bore 501 of the tubing connector 500. The liquid collector insert 400 is a cylindrical U-shaped shaped insert which fits tightly or is welded in the central bore 501 of the tubing connector body 500. As will be appreciated, the opposed ends 410 c, 41d of the insert can also be held in place by permitting the end of the tubing 300 in the threaded sections 504 to serve as stops to sandwich the insert 400 in place between two adjoining lengths of tubing 300. Holes 413 near the bottom 410 d of the collector 400 allow liquid to flow from A annulus into a circular lower groove 411 machined on the outer cylindrical surface 410 a of the insert 400. A similar groove 412 is located near the top 410 c of the insert 400. These two grooves 411, 412 are connected by a number (six in the illustration) of helical grooves 414 machined on the outer surface 410 a of the insert 400. When the insert 400 is pressed into the connector body core 501, liquid in the collector 400 can flow through the radial holes 413 into the lower circular groove 411 and from there through the restrictive helical channels 414, which serve as chokes to control the flow of pressurized liquid from the A annulus to the B annulus. The upper circular groove 412 on the insert body 400 registers with a number of radial holes 450 through the connector body 500. Liquid refrigerant sprays out through these holes 450 into the B annulus. The tubing connector, or refrigerant expansion control tube coupler 500 can be deployed in a tubing string at any desired coupling between adjacent tubing or pipe joints 300 in a tubing string. 

1. A method for mitigating the ice melting effects of heat transfer caused by the production of relatively hot fluids from an oil, gas condensate or gas well in a permafrost area, comprising the steps of: a. introducing one or more cold hydrate-forming fluids into an external ice-laden environment proximate the well in the area of such heat transfer; and b. permitting said one or more hydrate forming fluids to mix with any melt-water that may be present in said environment or that may subsequently form in said environment due to the loss of heat from the well so that said mixture of said one or more cold hydrate-forming fluids and melt-water form solid hydrates.
 2. The process of claim 1 wherein said one or more hydrate-forming fluids are selected from the group consisting of tetrahydrofuran, p-dioxane, CO₂, H₂S, and the low-molecular-weight hydrocarbons.
 3. The process of claim 1 wherein said one or more hydrate-forming fluids include at least one of tetrahydrofuran, p-dioxane, CO₂, and H₂S.
 4. A process for reducing ice melt in the vicinity of a glacier, ice dam, or other naturally occurring ice formation comprising the steps of: a. locating one or more zones in the vicinity of said glacier, ice dam, or other naturally occurring ice formation where melt-water exists or is likely to exist; b. introducing at least one cold hydrate-forming fluid into said one or more zones; and c. permitting said at least one hydrate forming fluid to mix with any melt-water that may be present in said one or more zones or that may subsequently form in said one or more zones so that said mixture of said at least one cold hydrate-forming fluids and melt-water form solid hydrates.
 5. The process of claim 4 wherein said hydrate-forming fluid is selected from the group consisting of tetrahydrofuran, p-dioxane, CO₂, H₂S, and the low-molecular-weight hydrocarbons.
 6. The process of claim 4 wherein said hydrate-forming fluids include at least one of tetrahydrofuran, p-dioxane, CO₂, and H₂S.
 7. An apparatus for collecting liquid formed from condensable or vaporizable materials in a low-pressure-gas-filled or partially evacuated annulus of an oil, gas condensate, or gas well comprising: a. an inner tubular member having an exterior wall surface; b. an outer tubular member axially surrounding said inner tubular member and having an interior wall surface; c. an annular space created between said inner tubular exterior wall surface and said outer tubular interior wall surface; and d. one or more weir members attached to said outer tubular interior wall surface, said one or more weir members comprising a bottom end having a floor member, one or more concentrically spaced apart annular wall members attached to said floor member, an open top end, and one or more fluid collection chambers created in the space between said one or more concentrically spaced apart annular wall members, said outer tubular member intended to be installed in said well such that said top end of said weir is oriented in a generally upward direction within said well so that annular liquid formed on said outer tubular member interior wall surface is permitted to flow generally downwardly along said outer tubular member interior wall surface and into said one or more fluid collection chambers.
 8. A method of well thermal management in a low-pressure-gas-filled or partially evacuated annulus of an oil, gas condensate, or gas well comprising the steps of: a. placing one or more weirs within said annulus, said annulus being generally defined as having an inner tubular member having an exterior wall surface; an outer tubular member axially surrounding said inner tubular member and having an interior wall surface; and an annular space created between said inner tubular exterior wall surface and said outer tubular interior wall surface; said one or more weir members being attached to said outer tubular interior wall surface, said one or more weir members comprising a bottom end having a floor member, one or more concentrically spaced apart annular wall members attached to said floor member, an open top end, and one or more fluid collection chambers created in the space between said one or more concentrically spaced apart annular wall members; said outer tubular member being installed in said well such that said top end of said weir is oriented in a generally upward direction within said well so that annular liquid formed on said outer tubular member interior wall surface is permitted to flow generally downwardly along said outer tubular member interior wall surface and into said one or more fluid collection chambers; and b. collecting and sequestering said formed annular fluid.
 9. The method of claim 8 wherein said method prevents establishment of an effective heat pipe or thermosyphon.
 10. The method of claim 8 wherein said method disrupts the patterns of convection in the gas present in said annulus.
 11. An expansion control coupler for use in oilfield annular tubing comprising: a. a cylindrical tubing connector body having an exterior surface and an interior surface, a central body section having an upper end and a lower end displaced between two threaded connector sections capable of receiving threaded tubing, and one or more liquid outlet holes proximate said upper end creating a conduit between said connector body interior surface and said connector body exterior surface; and b. a cylindrical capillary expansion groove insert fitted within said central body section comprising i. an outer annular wall member having an outer face and an inner face and an upper end and a lower end; ii. an annular liquid collection dam wall member having an outer dam face and an inner dam face and a dam upper end and dam lower end, said dam being connected at its bottom end to said bottom end of said outer annular wall member such that said annular dam wall member and said outer annular wall member exist in a substantially spaced-apart coaxial relationship; iii. a liquid collection zone created by the space between said annular dam member and said outer annular wall member; iv. a lower groove in said exterior surface of said outer annular wall member its proximate its lower end; v. an upper groove in said exterior surface of said outer annular wall member proximate its upper end; vi. one or more drainage holes in the lower groove to permit fluid communication between said liquid collection zone and said lower groove; and vii. one or more capillary grooves located in said outer face of said outer annular wall member connecting between said lower groove and said upper groove to permit fluid communication between said lower groove and said upper groove; said liquid outlet holes in said central body upper end being positioned to register with said upper groove of said outer annular wall member, said coupler providing fluid communication between said liquid collection zone and said connector body exterior surface.
 12. A well thermal management system for controlling fluid temperatures in fluids produced in oilfield well production tubing comprising: a. a well installation having a production tubing string producing fluids from a desired region of a subsurface formation to the surface; b. a first annulus tubing section axially surrounding at least a portion of said production tubing string, said first annulus having a top end located at the surface of said well installation and a bottom end located at a desired depth along said tubing string, said first annulus tubing section having an inside tubing wall surface and an outside tubing wall surface; c. a second annulus tubing section axially surrounding at least a portion of said first annular tubing section to the surface, said second annulus having a top end located at the surface of said well installation and a bottom end located at a desired depth along said first annulus; d. a refrigeration system having an outlet in fluid communication with said first annulus top end for introducing into said first annulus one or more desired refrigerants at a desired temperature(s) and pressure(s), and an inlet in fluid communication with said second annulus top end; e. one or more zones for collecting liquid formed on said inside tubing wall surface of said first annulus; f. one or more expansion control elements creating fluid communication between said first annulus and said second annulus at desired depths to permit the passage of said one or more refrigerants from said first annulus to said second annulus, said one or more expansion control elements being located proximate said one or more liquid collection zones; and g. conduit for directing fluid flow from said second annulus back to said inlet of said refrigeration system, said first and second annulus and said refrigeration system being tied together as a closed system.
 13. The system of claim 12 wherein said refrigeration system is selected from the group consisting of: vapor-compression refrigerator/heat pump cycle systems, vapor-absorption systems and gas cycle systems.
 14. The system of claim 12 wherein said refrigeration system is a vapor-compression refrigerator/heat pump cycle system using a compressor for introducing said one or more desired refrigerants, and further comprising a pressure regulation and monitoring system.
 15. The system of claim 12 wherein said one or more expansion control elements are selected from the group consisting of thermostatic expansion valves and simple capillary tubes.
 16. The system of claim 12 wherein a liquid collection zone is defined as the region immediately above said bottom end of said first annulus.
 17. The system of claim 12 wherein said liquid collection zones further comprise one or more liquid collection systems each comprising a concentric extended lip attached to said first annulus inside tubing wall surface at desired depths and wherein at least one of said one or more expansion control elements is placed in said one or more liquid collection systems to permit passage of fluid collected from said first annulus to said second annulus.
 18. A method for controlling fluid temperatures in fluids being produced to a surface oilfield well installation from production tubing located in desired regions of a subsurface formation comprising the steps of: a. providing a first annulus tubing section axially surrounding at least a portion of said production tubing string, said first annulus having a top end located at the surface of said well installation and a bottom end located at a desired depth along said tubing string, said first annulus tubing section having an inside tubing wall surface and an outside tubing wall surface; b. providing a second annulus tubing section axially surrounding at least a portion of said first annular tubing section to the surface, said second annulus having a top end located at the surface of said well installation and a bottom end located at a desired depth along said first annulus; c. providing a refrigeration system having an outlet in fluid communication with said first annulus top end for introducing into said first annulus one or more desired refrigerants at a desired temperature(s) and pressure(s), and an inlet in fluid communication with said second annulus top end; d. providing at desired locations within said first annulus one or more zones for collecting liquid formed on said inside tubing wall surface of said first annulus; e. providing one or more expansion control elements creating fluid communication between said first annulus and said second annulus at desired depths to permit the passage of said one or more refrigerants from said first annulus to said second annulus, said one or more expansion control elements being located proximate said one or more liquid collection zones; f. providing conduit for directing fluid flow from said second annulus back to said inlet of said refrigeration system; g. operating said first and second annulus and said refrigeration system as a closed system; h. directing a refrigerant vapor into said top end of said first annulus; i. collecting condensed liquid in said one or more liquid collection zones; j. directing said collected fluids through said one or more expansion control elements into said second annulus, and k. directing said fluids in said second annulus back to said inlet of said refrigeration system.
 19. The method of claim 18 wherein said first annulus is maintained at high temperature and high vapor pressure while substantially simultaneously maintaining said second annulus at low temperature and low vapor pressure.
 20. The method of claim 18 wherein said refrigeration system is selected from the group consisting of: vapor-compression refrigerator/heat pump cycle systems, vapor-absorption systems and gas cycle systems.
 21. The method of claim 18 wherein said refrigeration system is a vapor-compression refrigerator/heat pump cycle system using a compressor for introducing said one or more desired refrigerants, and further comprising a pressure regulation and monitoring system.
 22. The method of claim 18 wherein said one or more expansion control elements are selected from the group consisting of thermostatic expansion valves and simple capillary tubes. 